Australia’s desalination industry: from drought insurance to core water infrastructure

Australia’s desalination sector has moved from being a politically contested “last resort” to a mainstream part of urban water security. The industry was born out of the Millennium Drought, but its role has broadened: desal is now used not only for drought response, but also for resilience against poor raw-water quality during floods and bushfires, and as a way to underpin growth in cities and water-stressed regions. In Perth, desalination already provides roughly half of drinking water supply; in Melbourne, the Victorian Government has just ordered 150 GL from the Victorian Desalination Plant for 2026–27 after storages fell; and in South East Queensland and regional WA and SA, new desal projects are advancing from planning into delivery. (Water Corporation)

What follows is a practical snapshot of the sector: the main operating assets, the next wave of projects, how the industry evolved, and where the pressures and opportunities now lie.

Operating desalination facilities

Facility	Location	Capacity	Started / commissioned	Owner / operator	Cost (if available)
Perth Seawater Desalination Plant	Kwinana, WA	50 GL/yr	2006	Water Corporation	~A$387m
Southern Seawater Desalination Plant	Binningup, WA	100 GL/yr	2011 (Stage 1); 2014 full 100 GL	Water Corporation	n/a in source set
Sydney Desalination Plant	Kurnell, NSW	91.25 GL/yr	2010	Utilities Trust of Australia, managed by Morrison	~A$1.24bn
Gold Coast Desalination Plant	Tugun, Qld	~43–45.6 GL/yr	2009	Seqwater	~A$1.209bn
Adelaide Desalination Plant	Lonsdale, SA	100 GL/yr	2011–12	SA Water	~A$1.84bn
Victorian Desalination Plant	Wonthaggi, Vic	150 GL/yr	2012	State of Victoria / AquaSure PPP	A$3.5bn
Penneshaw desalination plants	Kangaroo Island, SA	0.4 ML/day + 2 ML/day	1999; late 2024	SA Water	n/a

Compiled from official utility and government sources. Perth Kwinana capacity/start/cost come from Water Corporation and WA budget papers; Binningup capacity and commissioning from Water Corporation; Sydney capacity/ownership from Sydney Desalination Plant and cost from official financial statements tabled in NSW Parliament; Gold Coast capacity and 2009 start from Seqwater, with capital cost from Queensland budget/parliamentary material; Adelaide capacity/start from SA Water and EPA SA, with project cost from SA Ombudsman/agency material; Victoria capacity, commissioning and cost from Victorian Government sources; Penneshaw details from SA Water. (Water Corporation)

Future and expanding projects

Project	Location	Capacity	Status / timing	Owner / operator	Cost (if available)
Alkimos Seawater Desalination Plant Stage 1	Alkimos, WA	50 GL/yr	Under construction; first water planned 2028	Water Corporation	A$2.8bn
Alkimos Stage 2	Alkimos, WA	+50 GL/yr (100 GL total)	Future expansion pathway	Water Corporation	included in future expansion planning
Eyre Peninsula Desalination Project	Billy Lights Point, SA	5.3 GL/yr	Under delivery; first water expected by end-2026	SA Water	~A$470m
Onslow Seawater Desalination Plant	Onslow, WA	1.5 ML/day initially (upgradeable to 2 ML/day)	Under construction; production scheduled 2026	Water Corporation	A$94m program
Dampier Seawater Desalination Plant Stage 1 + 2	Pilbara, WA	8 GL/yr total	Stage 1 due to begin supplying later in 2026; Stage 2 expected 2027	Rio Tinto / Water Corporation partnership	A$606m Stage 2 investment; plant referenced as A$1.1bn
Lower Great Southern proposed plant	Nanarup/Albany region, WA	3 GL/yr initial	Planning and community consultation; new source needed by 2030	Water Corporation	not yet stated
Gold Coast Desalination Plant expansion	Tugun, Qld	capacity increase not yet published in source used	Business case and investigations underway; Seqwater planning for delivery by 2030/31	Seqwater	A$30.5m planning/investigatory funding announced in 2024–25
New SEQ desalination plant (longer-term)	SEQ, likely northern corridor per program documents	not yet stated	Detailed business case being explored	Seqwater	not yet stated

These project details come from recent official announcements and program documents from Water Corporation, SA Water/SA Government, Seqwater, Rio Tinto and WA Government. (Western Australian Government)

How the sector evolved

The first big wave of Australian desalination investment was a direct response to the Millennium Drought. Perth moved first, bringing the Kwinana plant online in 2006, then the larger Binningup plant in stages from 2011. Queensland brought Tugun online in 2009. Sydney’s Kurnell plant followed in 2010, Adelaide’s Lonsdale plant in 2011–12, and Victoria’s Wonthaggi plant was fully commissioned in December 2012. (Water Corporation)

That first wave was shaped by urgency, large capital spending, and political controversy. Several projects were criticised for cost and periods of low utilisation after wetter years returned. But the strategic logic has strengthened over time. Climate change has reduced the reliability of traditional rainfall-fed systems, especially in WA. At the same time, large east-coast systems have learned that climate risk is not only about drought: floods, bushfires and raw-water quality disruptions can also reduce conventional treatment output, which is why utilities in Sydney and SEQ now emphasise desal’s role in operational resilience as well as drought response. (Water Corporation)

The current asset base

The national picture is uneven. Perth is the most mature desal market: Water Corporation says its Kwinana and Binningup plants together have the capacity to supply around half of local water needs, and recent WA material says desal now supplies roughly half of Perth’s drinking water. That makes WA the clearest example of desal shifting from contingency asset to base-load water infrastructure. (Water Corporation)

On the east coast, the big plants are more varied in how they are used. Sydney’s plant can now operate on a “flexible full-time basis” between about 20 GL and 91.25 GL a year, reflecting a more integrated role in the water system. SEQ keeps the Gold Coast plant in hot standby when not fully needed, but has also used it for flood resilience and to support maintenance elsewhere in the grid. Melbourne has gone from years of low or zero orders to a more active ordering pattern since 2016–17, and the latest 2026–27 order shows the plant is again being used as a material supply source rather than a purely symbolic backup. Adelaide’s plant remains the city’s only climate-independent source of drinking water. (Sydney Desalination Plant)

Victoria’s 2026–27 desal order matters

The most important current signal in the sector is Victoria’s latest order. On 7 April 2026, the Victorian Government confirmed a 150 GL desalinated water order for 2026–27. Melbourne Water said the order reflects hot and dry weather, lower rainfall, declining inflows and population growth; end-of-March 2026 storages were 67.1%, down from 78.6% a year earlier, the lowest end-of-summer level since 2020. The order follows a 50 GL order for 2025–26 and reinforces the view that the Wonthaggi asset is now an active part of water-supply balancing, not just a dormant insurance policy. (Melbourne Water)

The next phase of growth

The next build cycle looks more targeted than the first one. The standout project is Alkimos in WA, where Stage 1 will add 50 GL/yr and Stage 2 takes the site to 100 GL/yr. This is not just incremental capacity: it is a sign that Perth expects desal to remain a structural pillar of supply as rainfall declines. (Western Australian Government)

A second theme is the rise of regional desalination. SA’s Eyre Peninsula project, WA’s Onslow plant, the Dampier expansion in the Pilbara, and the proposed Lower Great Southern plant near Albany all show desal moving beyond capital-city drought planning into regional growth, mining-linked demand, groundwater substitution, and climate adaptation for smaller systems. (Housing and Urban Development)

Queensland is the other system to watch. Seqwater is progressing a business case to expand the Gold Coast Desalination Plant, and its program documents point to delivery of the expansion by 2030/31, alongside a longer-term major new water source. (Seqwater)

The industry’s main challenges

The first challenge remains cost and affordability. Desal plants are capital-intensive, and even when not heavily used they still carry fixed costs, maintenance requirements and energy exposure. That is one reason desal has often been politically contentious. (Water and catchments)

The second is energy. Reverse osmosis is proven and increasingly efficient, but it is still power-hungry relative to conventional surface water. Australian utilities are responding by pairing desal with renewable procurement and lower-emissions operating strategies, but the energy-water nexus remains central to project economics and public acceptance. (Western Australian Government)

The third is environmental and community acceptance. Intake and outfall design, brine dispersion, coastal amenity, marine ecology, construction impacts and visual footprint all matter. That is why newer projects such as Alkimos and Nanarup are being framed around lower-impact design, consultation and site selection. (Water Corporation)

A fourth challenge is integration with broader water portfolios. Desal is most valuable when it is part of a larger system that also includes dams, transfers, demand management, recycling and groundwater replenishment. Australia’s current planning increasingly treats desal as one element in a portfolio rather than a stand-alone answer. (Seqwater)

Outlook

The outlook for Australia’s desalination industry is strong. The country already has a mature base of large coastal assets, proven operating capability, and utilities that increasingly understand how to use desal flexibly. The next decade is likely to feature three trends: more base-load use in systems under chronic rainfall stress, especially WA; more targeted regional plants in exposed coastal communities and industrial corridors; and more portfolio integration with recycled water, groundwater replenishment and network planning. (Water Corporation)

The key commercial point is that desal is no longer just an emergency measure. In Australia, it is becoming a normal infrastructure class: expensive, energy-sensitive and politically visible, but increasingly indispensable.

If you want, I can turn this into a more polished Northstream-style blog article with a sharper intro, subheads, and a more publication-ready tone for your site.

Wired for Change: Australian Electricity Distribution in the Energy Transition

Australia’s electricity distribution companies face a paradox: the world’s most solar-saturated grid is forcing them to invest more than ever in a network that fewer customers rely on for power — and regulators, ratepayers and shareholders are all feeling the strain.

Metric	Figure
Rooftop solar installed capacity (end 2025)	28.3 GW
Rooftop solar installations nationwide	4 million+
NEM electricity from rooftop solar (H2 2025)	14.2%
Home batteries installed nationally	454,000+

Not long ago, electricity distribution was considered one of the most predictable businesses in the world. Networks were built to carry power in one direction — from large generators, down through substations and wires, to homes and businesses. Revenue was stable; demand grew steadily; the regulatory compact was simple.

That world is gone. Australia now leads the globe in rooftop solar uptake per capita, and the consequences are reshaping the fundamental economics of regulated electricity distribution. Across the National Electricity Market (NEM), Distribution Network Service Providers (DNSPs) — companies like Ausgrid, Endeavour Energy, Energex, Ergon Energy, SA Power Networks, AusNet, CitiPower, Powercor, United Energy, Essential Energy, Evoenergy and JEN — are grappling with a set of interlocking challenges that touch every part of their business, from capital planning to regulatory submissions to the tariffs customers pay.

1. The Solar Storm: A Grid Built for One Direction of Flow

Australia’s rooftop solar revolution has been staggering in its scale and pace. By end 2025, total installed rooftop solar capacity reached 28.3 GW — eclipsing the country’s entire 22.5 GW coal-fired generation fleet. More than four million individual systems sit on homes and businesses across the NEM, and the average new system size has climbed to 10.2 kW as the market matures. During the first half of 2025, rooftop solar contributed 14.7% of the NEM’s total generation — more than utility-scale solar (9.3%), wind (13.7%), hydro (4.9%) or gas (3.5%) individually.

AEMO projects rooftop PV capacity will grow from around 25 GW today to 42.5 GW by 2036, and a remarkable 87 GW by 2050 — a more than three-fold increase. Nearly 80% of detached homes in the NEM are expected to carry solar panels by mid-century.

South Australia case study: Renewables supplied 100% of South Australia’s electricity demand for 27% of all hours in 2024 — roughly 99 full days. On 19 October 2024, a record 30-minute minimum operational demand of minus 205 MW was recorded as rooftop solar swamped the grid. Over 53% of SA homes have solar panels.

The consequences for distribution networks are profound. These networks were engineered for one-way power flow from large centralised generators. When rooftop solar generation exceeds local consumption — increasingly common on sunny weekday mornings — power flows backwards up the network, towards the substation and potentially into the transmission system. This reversal creates voltage management challenges, increases the risk of network congestion and equipment overload, and can require costly network augmentation to accommodate.

“In the middle of a sunny day, about 40% of Australian homes generate their own power from rooftop solar. When generation exceeds consumption, excess power flows back to the grid — pushing local networks to their capacity limits.”— CSIRO Senior Principal Research Scientist Dr Julio Braslavsky

2. Batteries and EVs: Complexity Squared

The second wave of the distributed energy revolution is now well underway. Home battery installations surged dramatically in the second half of 2025, with a four-fold increase in installation rates compared to the same period in 2024. By end 2025, over 454,000 home batteries were installed nationally. AEMO’s Draft 2026 Integrated System Plan foresees 27 GW of behind-the-meter batteries by 2050.

Electric vehicles add another dimension of uncertainty and opportunity. The 2026 ISP projects 9 GW of storage capacity from EVs by 2050, when 80% of all vehicles are expected to be battery-powered. EV charging loads are large — a typical home EV charger draws 7–22 kW — and have highly variable timing. Uncoordinated charging during evening peaks could undo years of demand management progress, requiring expensive network augmentation. Coordinated charging, by contrast, could substantially reduce peak demand and allow networks to avoid or defer costly upgrades.

The combination of rooftop solar, batteries and EVs creates what network planners call a “duck curve” problem — a dramatic fall in net demand during sunny midday hours, followed by a steep evening ramp as solar generation drops and households plug in their cars and switch on appliances. Managing this ramp requires fast-response peaking capacity and network infrastructure capable of handling bi-directional power flows.

3. The Investment Paradox: Spending More on a Grid Used Differently

Here lies the central paradox facing regulated distribution businesses. Network utilisation is not increasing in the traditional sense — midday rooftop solar means many parts of the low-voltage network are far less loaded than they were a decade ago. Yet the investment required to manage the energy transition is rising sharply, for several distinct reasons:

Ageing asset replacement. Much of the distribution infrastructure built during the postwar expansion in the 1960s–80s is reaching end of life simultaneously. This creates an unavoidable wave of replacement capex — the AER approved $2.67 billion in net capex for Ausgrid’s distribution network alone for the 2024–29 period.
Two-way network upgrades. Legacy low-voltage feeders, substations and protection systems must be upgraded to handle bi-directional power flows safely. Smart inverter technology, voltage control equipment and advanced monitoring all require capital investment with a regulatory case that is often difficult to make under traditional frameworks.
DER integration infrastructure. Connecting, monitoring and coordinating millions of distributed energy resources — solar inverters, batteries, EV chargers, smart meters — requires advanced metering infrastructure, communications networks, and sophisticated control systems. These are genuine new-category costs.
Electrification-driven demand growth. As households and businesses switch from gas to electric appliances, grid consumption is forecast to roughly double by 2050. AEMO estimates business and industry consumption could rise from 145 TWh today to nearly 345 TWh by 2050.

The Institute for Energy Economics and Financial Analysis (IEEFA) has flagged a concerning pattern: all three DNSPs that submitted 2025–30 revenue proposals in January 2024 — SA Power Networks, Ergon Energy and Energex — proposed capex increases of 20–22% compared with the prior regulatory period. IEEFA questioned why these increases were so substantial given low network utilisation and rising DER uptake, warning of the risk of over-investment comparable to the “gold-plating” era of 2006–2015 that drove sharp increases in consumer electricity bills.

4. The Regulatory Asset Base Squeeze

The Regulatory Asset Base (RAB) is the cornerstone of economic regulation for Australian electricity networks. The RAB represents the economic value of the assets a network uses to provide regulated services. The AER allows networks to earn a regulated rate of return on their RAB and to recover the RAB’s value over time through regulated depreciation. When the RAB grows — driven by higher approved capex — the return on capital and depreciation components both increase, flowing directly through to higher network tariffs and ultimately higher consumer bills.

Network	Period	Outcome	Change
Energex (Qld)	2025–30	$7.7bn approved revenue	+16% (+$1.0bn)
Ausgrid (NSW)	2024–29	$2.67bn net capex approved	Distribution RAB +16%
Energex avg tariff	2025–30	+4.6% p.a. real increase	+7.4% p.a. nominal
SA Power Networks	2025–30 proposal	20–22% capex increase proposed	vs 2020–25 period

Inflation and higher interest rates have compounded the challenge. The AER’s Rate of Return Instrument (updated March 2024) sets the WACC applied to regulated RABs. With real interest rates rising from near-zero levels, the return on capital component of allowed revenue has increased materially even before any RAB growth. The AER’s Energex determination illustrates this: approximately 45% of the $1 billion revenue increase over the prior period was attributable to higher inflation and interest rates.

5. Regulatory Submissions: A New Vocabulary

Australia’s economic regulation framework — the National Electricity Rules (NER) and AER regulatory guidelines — was primarily designed for a simpler era. The rules are better suited to evaluating traditional capex proposals than to assessing novel proposals to integrate distributed energy resources, procure services from third-party batteries, or invest in advanced monitoring and control systems.

DNSPs must demonstrate that proposed expenditure satisfies the “capex and opex criteria” in the NER — that expenditures are efficient, prudent, and no more than necessary to meet regulatory obligations. This creates a high evidential bar for new categories of spending.

Regulatory framework gap: IEEFA notes that “totex” regulation — combining capex and opex into a single allowance as used widely in Great Britain and Europe — has not been adopted in Australia. Under the current regime, networks retain a “capex bias” incentive, since capital investment adds to the RAB and earns a regulated return, whereas using third-party DER for network services is treated as opex with less certain regulatory recovery.

A further tension exists around Consumer Energy Resources (CER) in network planning. Research cited by the AEMC suggests effective CER integration could avoid up to $45 billion in grid-scale investment by 2050. Yet current regulatory tools make it difficult for DNSPs to formally substitute DER-provided services for traditional network augmentation, and performance incentive mechanisms are not yet aligned with decarbonisation outcomes.

Networks are also increasingly required to demonstrate consumer engagement outcomes in their regulatory proposals. Ergon Energy and Energex completed extensive five-phase engagement plans ahead of their 2025–30 submissions — a significant shift from the expert-driven processes of earlier regulatory cycles.

6. Tariff Reform: Pricing the Two-Way Grid

Network tariff reform is perhaps the most complex and contested dimension of the transition challenge. Flat volumetric tariffs (cents per kilowatt-hour consumed) send no signal about when or how a customer uses the network. As of 30 June 2024, only 37.35% of residential NEM customers were on a cost-reflective network tariff — an increase of around 6% from the prior year, but still leaving nearly two-thirds of customers on legacy flat or block tariffs.

The emergence of export charges — levied when solar customers push power back into the network during congested periods — represents a significant and politically sensitive innovation. Essential Energy’s “Sun Soaker” tariff, the default for new residential connections from 1 July 2024, introduces both an export charge and an export rebate, rewarding exports during the evening peak (around 11 cents/kWh rebate) and penalising congestion-causing midday exports (less than 1 cent/kWh above a free daily threshold of 7.5 kWh).

SA Power Networks’ “Solar Sponge” trial tariff similarly attempts to shift load and exports to the middle of the day — the period of maximum solar generation and minimum grid demand — by offering free export allowances between 10am and 4pm.

EV-specific tariffs are also emerging. Evoenergy in the ACT proposed controlled load tariffs for EV owners, offering lower prices during off-peak periods (9am–5pm and 10pm–7am) to discourage evening peak charging. Vehicle-to-grid (V2G) technology — allowing EV batteries to export power back to the grid during peak periods — is a particularly promising but technically and commercially complex frontier.

7. Five Pressure Points: What the Next Regulatory Cycle Must Resolve

RAB inflation and interest rate exposure. Regulatory periods locked in at higher WACCs mean network revenues — and consumer bills — will remain elevated even if wholesale conditions ease. DNSPs must make the case for efficient capex while regulators must resist over-allowances.
Smart meter rollout and tariff transition. Federal and state mandates to expand smart meter coverage are essential. Without advanced meters, export charges and time-of-use pricing cannot be operationalised at scale.
DER orchestration at scale. AEMO’s distributed energy resource management system (DERMS) frameworks need to mature. DNSPs need regulatory certainty that investments in DER coordination infrastructure will be recoverable through the regulatory process.
EV charging infrastructure pressure. As EV penetration accelerates toward mass-market levels, distribution feeders in suburban areas face material load increases — particularly in evenings. Investment decisions made now will determine whether this transition is managed smoothly or results in reliability failures.
Regulatory framework redesign. IEEFA and others have called for a first-principles review of distribution network economic regulation — examining totex models, DER market frameworks, and performance incentive mechanisms better aligned with decarbonisation outcomes.

Conclusion

Australia’s regulated electricity distribution businesses are not facing a temporary disruption — they are at the centre of a fundamental, multi-decade transformation of the energy system. Networks built for one-way power flows must be upgraded for a bi-directional, digitally managed system; investment requirements are rising even as traditional load profiles flatten; tariff structures must evolve from simple volume-based charges to sophisticated time-variant price signals; and regulatory frameworks designed for a simpler era must be adapted — or replaced — to enable the least-cost energy transition.

The stakes for consumers are high. AEMO’s Draft 2026 ISP estimates the total cost of delivering the energy transition at $128 billion to 2050. How much of that investment flows through network RABs, and whether it is efficient and well-targeted, will be a central question of the next decade of regulatory policy.

The good news is that with the right policy and regulatory settings — cost-reflective tariffs, effective DER integration, proper performance incentives, and disciplined regulatory oversight — Australia’s extraordinary distributed energy resource base could become a powerful asset for managing the transition. The alternative — an uncoordinated buildout of conventional network infrastructure that fails to harness the value of 28+ GW of rooftop solar and hundreds of thousands of home batteries — would deliver a far more expensive outcome for Australian consumers and the economy.

Key sources: Clean Energy Council, Clean Energy Australia Report 2025; Australian Energy Regulator, State of the Energy Market 2025; AEMO, Draft 2026 Integrated System Plan; AER final decisions on Ausgrid (2024–29), Energex and Ergon Energy (2025–30); IEEFA, Reforming the Economic Regulation of Australian Electricity Distribution Networks (May 2024); AEMC, Navigating the Energy Trilemma (August 2025); CSIRO, Balancing Australia’s Ocean of Electricity (October 2025); ElectraNet, 2025 Transmission Annual Planning Report.

This article is for informational and analytical purposes only and does not constitute financial, legal or investment advice.

Why Most BESS Revenue Models Fail Under High FCAS Volatility

Battery Energy Storage Systems (BESS) are becoming central to NEM stability, arbitrage, and renewables integration. Yet despite rapid deployment, financial outcomes continue to diverge sharply from pre-investment revenue modelling. The common culprit: traditional modelling frameworks break down under high FCAS volatility.

2023–25 has delivered some of the most volatile FCAS conditions since the introduction of the contingency and regulation markets. Price spikes have become less predictable, event durations have become shorter and more clustered, and inter-regional price separation has intensified. Most BESS pro formas—built on smoothing assumptions or simplified dispatch logic—simply cannot capture real-world volatility.

The result? Systematically biased revenue forecasts, mis-optimised bidding behaviour, and an underestimation of portfolio risk.

This article sets out five reasons most BESS revenue models fail under high FCAS volatility, and how advanced modelling—like Northstream Analytic’s PowerStream short-term dispatch engine—overcomes these structural weaknesses.

1. FCAS Volatility Is Not Normally Distributed — But Most Models Pretend It Is

Many investment decks and banker-friendly models still assume:

Mean-reverting FCAS prices
Log-normal or normal distributions
Smooth temporal volatility without clustering

But the NEM’s FCAS markets consistently exhibit:

Heavy-tailed price distributions
Clustering of extreme events
Sudden regime shifts
State-dependent volatility (e.g., islanding risk, unit outages, wind ramps)

This means that using a single “average” FCAS price per service category is mathematically invalid. The tails drive the earnings: a handful of intervals can deliver >50% of annual FCAS revenue, especially for Raise/Lower Contingency services.

When models smooth this out, they under-forecast revenue in good years and over-forecast in bad years, giving investors a false sense of stability.

2. Static Capacity Allocation Assumptions Break During Price Spikes

A typical investor model sets fixed percentages of battery capacity to:

Energy arbitrage
FCAS regulation
FCAS contingency

But in real operations:

Energy and FCAS revenue stacks interact dynamically
The optimal allocation changes every 5 minutes
FCAS price spikes alter opportunity cost instantly
State of Charge (SOC) constraints limit which markets are viable

Static partitioning therefore suppresses upside in volatile FCAS conditions.

For example, during a high Raise 6-second event, the optimal strategy may shift from energy discharge to contingency enablement—but this shift is state-dependent and price-dependent, not rule-based.

Models that do not simulate real bidding strategy + SOC dynamics will systematically miss this.

3. SOC Constraints Under Volatility Create Nonlinear Profit Paths

Most simplified revenue models treat SOC as a linear constraint:

“Battery charges at low price, discharges at high price.”

Under FCAS volatility, SOC is instead a multi-dimensional optimisation problem involving:

Enablement depth
High-price tail events
Energy lost to regulation
Cycling limits and throughput penalties
Interaction with real-time AGC dispatch

This creates nonlinearities such as:

Being full too early → missing a late-day FCAS spike
Being empty during islanding risk → missing Raise contingency
Misaligned SOC trajectory → forced charging during expensive intervals

These complexities lead to revenue paths that no spreadsheet “averaging logic” can reasonably reproduce.

Only a constraint-based dispatch model can capture these dynamics.

4. FCAS Enablement and Compliance Are Not Perfectly Efficient

Real-world BESS operation loses revenue because:

Enablement often < 100% due to AGC behaviour
Causer-pays factors penalise poor performance
Compliance events reduce available MW
AGC movement consumes energy and reduces SOC stability
Thermal and inverter constraints limit maximum contingency enablement

Most revenue models assume perfect availability across all FCAS services.

This is rarely true. In fact, measured availability for some NEM assets can be as low as 70–80% after accounting for compliance and physical derating.

Ignoring this leads to:

Overestimated FCAS revenue
Underestimated degradation cycles
Incorrect valuation of control system quality

These errors compound under volatility.

5. Volatility Interacts With Degradation — A Hidden Cost

High FCAS volatility encourages batteries to chase short, high-value events.

But this often increases:

Cycling depth
Micro-cycling from AGC
C-rate stress
Temperature-related degradation

Degradation is nonlinear, not proportional to MWh throughput. One week of extreme FCAS activity can generate disproportionately large degradation events.

Simplified models typically assume:

A constant $/MWh degradation cost
Even cycling over time
No interaction between volatility and cell temperature

This is incorrect.

As FCAS volatility grows, ignoring nonlinear degradation overstates revenue and understates O&M reserves.

What a Valid BESS Revenue Model Must Include in a High-Volatility FCAS World

A robust model must integrate:

1. Five-minute NEMDE-aligned price simulation

Including scenario-based volatility and tail-event structure.

2. Full SOC trajectory modelling

Respecting charge/discharge rates, ramping, and energy constraints.

3. Co-optimised energy + FCAS bidding

Not preset allocations.

4. Compliance, enablement and AGC realism

Using empirical derating factors or control-loop simulation.

5. Nonlinear degradation modelling

Based on depth-of-cycle and stress factors.

6. Locational constraints and network constraints

Including MLF variability, curtailment risk, and islanding probabilities.

Conclusion: FCAS Volatility Rewards the Prepared and Punishes the Simplistic

As the NEM becomes more dynamic and renewable penetration increases, FCAS volatility is structurally rising—not falling. Batteries positioned to respond intelligently to this volatility will outperform their peers. But that requires models that reflect market reality, not spreadsheet mythology.

Most BESS investment models fail because they smooth what should be spiky, simplify what is nonlinear, and ignore what is stochastic.

If developers, investors, and operators want accurate forecasts, they need modelling frameworks built for volatility, not stability.

Northstream Analytic’s PowerStream modelling stack is built for this new world.

If you’d like us to run a project-specific BESS revenue assessment, reach out.

COP 30 coal pledges flow through to projected LNG demand: NS-WEM model LNG updates

Global energy markets are shifting again. At COP29 in Baku, governments launched a coordinated push for No New Coal, and the early outcomes of COP30 in Belém have continued the theme. The world is talking a big game —toward a phase-out of unabated coal power. For LNG markets, particularly through the 2030s, this has major implications if borne out in the power generation mix.

At Northstream Analytic, we have updated our NS-WEM world energy model to incorporate these scenarios. The results suggest a tightening in global LNG markets as coal-dependent countries turn to gas as well as renewables and nuclear.

Figure 1: updated NS-WEM LNG projected demand-supply balance to 2050 (COP 30 Powering Past Coal scenario)

1. Roadmap to Phase Out Fossil Fuels?

The political momentum against coal has accelerated significantly since 2024, at least in the war of words.

COP29 – The No New Coal Pledge

At COP29, 25 countries and the EU launched the Call to Action for No New Coal, a diplomatic initiative to end the construction of new unabated coal power plants and to reflect this commitment in upcoming Nationally Determined Contributions (NDCs). While not a binding global moratorium, the pledge marked a clear shift: coal expansion is now politically unpalatable for most advanced economies.

COP30 – Toward a Planned Fossil Fuel Phase-Out

COP30 has gone a step further. More than 80 countries are backing text calling for a managed phase-out of fossil fuels, with coal identified for early retirement. Side announcements include updated coal exit timelines, expanded renewable and nuclear roadmaps, and early drafts of “just transition” coal retirement strategies. Coal is on a downward trajectory in global policy aspirations.

2. South Korea’s Move: Joining the Powering Past Coal Alliance

One of the most significant coal announcements at COP30 comes from South Korea—a major industrial economy with one of the largest coal fleets in the OECD.

At COP30, South Korea announced that it would phase out thermal coal by 2040 and formally joined the Powering Past Coal Alliance (PPCA). This places the country in the group of advanced economies committed to ending new unabated coal development and charting an orderly coal exit.

The Implications

South Korea’s electricity mix is currently anchored by nuclear, gas, and coal. Coal still provides roughly 30% of its electricity, but the new commitment accelerates planned retirements. In practice, Korea will:

Retire and repurpose existing coal power stations (including possible CCS conversions).
Convert a portion of these plants to LNG-fired generation.
Expand nuclear capacity to provide stable, low-carbon baseload.
Maintain gas as a reliability and flexibility source through the 2030s.

Civil society groups are pushing for an earlier coal phase-out (2030) and a cap on gas consumption, but these are not yet reflected in official policy.

3. What This Means for LNG Demand

The coal phase-out commitments emerging from COP29 and COP30 have two competing effects on LNG markets.

a) Upward Pressure: Gas as the Bridge Fuel

For many countries—particularly in Asia—gas remains the only mature, dispatchable alternative to coal during the 2030s while renewables, grids and storage scale up. South Korea’s decisions reinforce this dynamic:

Retired coal capacity will partly shift to LNG.
26 coal units are slated for repurposing to gas and possibly CCS.
Gas-fired generation remains central to system reliability.

This mirrors broader emerging market trends. As coal retires faster, LNG demand rises—at least temporarily. This is borne out continuing LNG deal flow, and as countries continue to move away from reliance on Russian gas.

Table 1: Recently signed LNG supply deals

Buyer / Counterparty	Supplier / Counterparty	Volume	Start Date	Duration	Price / Pricing Mechanism
Uniper (Germany)	Tourmaline Oil (Canada) via US liquefaction	~0.56 million t/yr	2028	~8 yrs	Net-back pricing linked to the European TTF hub (gas sold to TTF minus shipping & handling) (Energy Intelligence)
Centrica (UK)	Tourmaline Oil (Canada) via US liquefaction	~0.35 million t/yr	2028	~10 yrs	Net-back pricing linked to TTF minus shipping & handling (Energy Intelligence)
MVM (Hungary)	Engie (French utility trader)	~0.30 million t/yr	2028	~10 yrs	Delivered ex-ship (d.e.s.) basis, predominantly from US volumes (Energy Intelligence)
MVM (Hungary)	US supplier (unnamed)	~0.30 million t/yr	2028	~5 yrs	Not specified (Energy Intelligence)
Naturgy (Spain)	Venture Global (US exporter)	~1.00 million t/yr	2030	~20 yrs	FOB (free-on-board) basis; destination-free delivery (Energy Intelligence)
Atlantic‑See LNG (Greece)	Venture Global (US exporter)	~0.50 million t/yr	2030	~20 yrs	FOB basis; destination-free delivery (Energy Intelligence)

b) Downward Pressure: The Growing Anti-Gas Policy Frontier

However, LNG growth is capped by several structural factors:

The nuclear renaissance in key markets (including Korea).
Declining costs of solar, wind, and battery storage.
Rising scrutiny of methane emissions in gas supply chains.
Concerns about locking in long-lived gas assets that could be stranded by the 2040s.

Even in South Korea, climate organisations argue that gas should peak before 2030 and decline thereafter. Whether the government ultimately follows this advice will determine the shape of long-run LNG demand.

4. Northstream’s NS-WEM Results: LNG Tightens in the 2030s

Northstream Analytic’s NS-WEM model has been updated with scenarios for COP commitments, coal retirement strategies, and country-level power sector plans. Under the policy settings announced so far, the model indicates:

▶ LNG markets tighten materially through the 2030s.

Coal may exit faster than previously expected across multiple regions.
Gas fills much of the transitional gap before large-scale renewables, storage and nuclear are fully built out.
Upstream LNG investment has been cautious due to long-term decarbonisation uncertainty, but eventually catches up to rising demand.

The result is a decade of structurally firm LNG demand from the late 2020s into the 2030s.

However, the NS-WEM also shows that beyond the mid-2030s, LNG demand plateaus and risks a decline if accelerated gas phase-down policies take hold—especially in Europe and advanced Asia.

5. Strategic Takeaways

For policymakers

Coal phase-out initiatives must be paired with clear long-term gas transition strategies to avoid locking in emissions and stranded assets.

For LNG market participants

The 2030s are shaping up as a period of tight LNG balances, supporting pricing strength and contract demand.
But asset lifetimes beyond 2040 require careful risk assessment.

eWaste not want not: Australia’s place in the global eWaste policy landscape

Electronic waste (e-waste) is basically any discarded product with a plug or a battery – from phones, laptops and TVs through to fridges, solar panels and EV batteries. The UN and WHO define it as end-of-life electrical and electronic equipment that often contains hazardous substances (e.g. lead, mercury, brominated flame retardants) and valuable critical raw materials (copper, gold, rare earths). (UNDRR)

Globally, the problem is now on a different scale:

62 million tonnes of e-waste were generated in 2022 (7.8 kg per person), and we’re on track to reach 82 million tonnes by 2030. (E-Waste Monitor)
Only ~22% of that was formally collected and recycled; the rest is landfilled, informally processed or unaccounted for, wasting around US$62 billion in recoverable materials and causing serious pollution risks. (UNITAR)

Australia is a high-intensity player:

Australia generates ~580,000 tonnes of e-waste a year, and the average Australian produces around 22 kg per person – nearly three times the global average. (The Guardian)
An estimated 23 million mobile phones are sitting unused in drawers, plus many more ending up in landfill. (The Guardian)

So the policy question is: how do you keep the toxics out of people and ecosystems, stop data breaches, and capture the metals and materials back into the economy?

Below is a structured review of how major jurisdictions tackle that, where Australia sits, and where policy probably needs to go.

1. Core policy tools used internationally

Most countries mix and match a common toolkit:

Extended Producer Responsibility (EPR): producers/importers pay for and organise collection and recycling, often via collective schemes. (epr.sustainablepackaging.org)
Landfill bans / disposal restrictions: prohibit e-waste from general waste streams (e.g. Victoria, WA, parts of the EU). (Essential Services Commission)
Take-back schemes: free drop-off at retailers, councils and dedicated sites, funded by producers (EU, Canada, NTCRS in Australia). (Environment)
Eco-design / hazardous substance restrictions: requirements to minimise certain chemicals and to design for repair and recycling (EU RoHS, Korea and Japan’s resource circulation laws). (eLaw)
Export controls & Basel Convention implementation: managing transboundary movement to avoid “waste colonialism” – something many countries still struggle with (see recent reporting on US e-waste exports to Southeast Asia). (AP News)

How each country combines these gives you the comparative picture.

2. International approaches – who’s doing what?

European Union – WEEE “gold standard”

The WEEE Directive 2012/19/EU sets EU-wide rules for collection, treatment and recycling of e-waste. (Environment)
Producers finance systems that must meet high collection and recovery targets (e.g. 65% of average EEE placed on the market or 85% of WEEE generated). (Environment)
Strong focus on EPR, hazardous substance control (via RoHS), and increasingly on circular economy and critical raw materials recovery. The Directive is currently being evaluated with a 2026 revision expected to further tighten EPR and collection rules. (Environment)

Take-away: high coverage, binding targets, strong producer obligations, harmonised across member states.

Japan – tightly managed with consumer fees

The Home Appliance Recycling Law (2001) covers TVs, air conditioners, fridges/freezers and washing machines/dryers. Consumers pay a recycling fee, retailers take back appliances, and manufacturers must meet recycling rate targets (55–82%). (Panasonic)
The Act on Promotion of Recycling of Small Waste Electrical and Electronic Equipment expands to a broad set of small appliances, with municipalities organising collection and certified recyclers doing the processing. (Japanese Law Translation)

Take-away: clear roles for manufacturers, retailers, local government and consumers; high recycling rates but with visible consumer charges.

South Korea – resource circulation model

The Act on Resource Circulation of Electrical and Electronic Equipment and Vehicles (EEEV Act) requires producers to meet recycling obligations, design products for recyclability and restrict hazardous substances. (eLaw)
There are explicit recycling quotas and a strong focus on precious and rare metals recovery. (IEA)

Take-away: advanced integration of EPR with eco-design and resource-security goals.

China – WEEE fund scheme

China’s WEEE system is built around the Regulations on the Administration of the Recovery and Disposal of Waste Electrical and Electronic Products and a national disposal fund created in 2011. (Ministry of Ecology and Environment)
Producers and importers pay fees into the fund; licensed recyclers receive subsidies per unit of e-waste treated, with a product catalogue specifying covered items. (Ministry of Ecology and Environment)

Take-away: large-scale, centralised financing mechanism; strong on formal sector infrastructure, but informal recycling and enforcement remain issues.

Canada – provincial EPR for electronics

Canada uses provincial EPR programs: most provinces require producers/importers to finance collection and recycling of electronics (and now packaging), within a broad EPR framework. (Landbell Canada)
Coverage and targets differ by province, but the direction of travel is towards more comprehensive and harmonised EPR across materials. (H2 Compliance)

Take-away: strong EPR logic, but fragmented and variable performance between provinces.

United States – patchwork and export issues

No federal e-waste law; management is via a mix of EPA regulations and state-level EPR laws. There are over 140 EPR laws across 35 states, but only some cover electronics. (Environmental Protection Agency)
Recent investigations show large volumes of US e-waste exported to Southeast Asia and the Middle East under vague trade codes, despite Basel-style controls. (AP News)

Take-away: innovation and private certification (e.g. R2/e-Stewards), but nationally inconsistent and prone to “waste leakage” offshore.

Where does Australia sit in this landscape?

Broadly, ahead of the US at federal level, roughly comparable to Canada, but behind the EU/Japan/Korea on coverage, stringency and circular-economy integration.

3. Australia’s e-waste policy history and current settings

3.1 National waste and circular economy framework

National Waste Policy (2009, updated 2018) sets the high-level direction to avoid waste, increase resource recovery and protect the environment.
The National Waste Policy Action Plan 2019 set national targets including:
- 10% reduction in total waste per person by 2030
- 80% average resource recovery rate from all waste streams by 2030
- bans on export of certain wastes. (DAFF)
In 2024, a new National Waste Policy Action Plan was released, explicitly anchoring the transition to a “safe circular economy” and aligning with SDG 12. (DCCEEW)

E-waste is nested inside this broader circular-economy narrative.

3.2 Product Stewardship Act, NTCRS and B-cycle

Product Stewardship Act 2011 / Recycling and Waste Reduction Act 2020

The Product Stewardship Act 2011 created a framework for mandatory, co-regulatory and voluntary schemes to manage products’ lifecycle impacts. (DCCEEW)
It now operates through the Recycling and Waste Reduction Act 2020, which continues to underpin national product stewardship schemes, including e-waste. (DCCEEW)

National Television and Computer Recycling Scheme (NTCRS)

Launched in 2011; currently operates under the 2020 Act. (DCCEEW)
Co-regulatory EPR scheme: importers and manufacturers of TVs, computers, printers and IT peripherals above a threshold must join approved arrangements that fund free collection and recycling for households and small businesses. (epa.nsw.gov.au)
The scheme has reportedly recycled over 360,000 tonnes of e-waste since inception, with targets around 66,000 tonnes per year in recent years. (DCCEEW)

Battery stewardship – B-cycle

B-cycle is Australia’s accredited national battery stewardship scheme, authorised by the ACCC and backed by Commonwealth, state and territory governments. (B-cycle)
It covers loose batteries (AA/AAA, rechargeables etc.), with producers and retailers funding collection and recycling; the aim is to create a circular system for batteries and reduce fire and toxicity risks. (B-cycle)

These schemes put Australia in the “serious but narrow” camp: some product groups are well covered; others are barely touched.

3.3 State and territory measures

Victoria banned all e-waste from landfill in July 2019 – anything with a plug, battery or power cord must go to designated drop-off points, not household bins. (Essential Services Commission)
Western Australia introduced a phased e-waste-to-landfill ban from 1 July 2024, starting with a defined list of “regulated e-waste” items. (Western Australian Government)
Other states and territories have a mix of local programs and transfer-station arrangements, but no nationwide landfill ban yet.

3.4 E-Stewardship and the “Wired for Change” reforms

Recognising that NTCRS + B-cycle only cover a slice of the e-waste stream, the Commonwealth has shifted to an “e-stewardship” agenda:

The DCCEEW E-Stewardship in Australia page (2023) flags a commitment to develop a mandatory product stewardship scheme to reduce waste from small electrical products and solar PV systems. (DCCEEW)
In June 2023, the “Wired for Change: Regulation for small electrical products and solar photovoltaic system waste” discussion paper proposed regulation to:
- reduce harmful materials going to landfill
- increase recovery and reuse of valuable materials
- expand stewardship beyond TVs/computers to everyday electronics and solar panels. (Google Cloud Storage)
Ministerial priority lists in 2025 continue to highlight small electricals and solar PV as stewardship priorities, suggesting the government intends to move towards mandatory participation. (DCCEEW)

At the same time, evidence work such as the E-Product Stewardship Evidence Report shows Australian per-capita e-waste at 20.4 kg in 2019, projected to 23.4 kg by 2030, with only about 54% collected and an even smaller share actually recycled. (DCCEEW)

4. How Australia compares

Across key dimensions:

Coverage of products

Leaders (EU, Japan, Korea, China): broad coverage – large and small appliances, IT, consumer electronics, often vehicles and PV as well.
Australia: strong coverage of TVs, computers, printers and IT peripherals and loose batteries, but no national scheme yet for most small appliances, whitegoods, PV systems or embedded batteries, although reforms are in train. (DCCEEW)

Legal architecture and targets

EU/Japan/Korea have binding collection and recycling targets per product category, with relatively strong enforcement and eco-design linkages. (Environment)
Australia has national waste targets but e-waste-specific targets mainly sit at the scheme level (NTCRS, B-cycle), not as comprehensive legal obligations across all devices.

Landfill and export controls

Victoria and WA’s bans put parts of Australia close to EU practices, but there is no national e-waste landfill ban yet. (Essential Services Commission)
Like many countries, Australia still faces challenges tracking exported e-waste, but is less notorious than the US in recent reporting. (AP News)

Performance

Australia’s 22 kg e-waste per capita is much higher than the global average (~7.8 kg), but collection and recycling rates are middling and heavily concentrated in a few regulated product groups. (The Guardian)
EU and some East Asian systems achieve higher formal recycling rates but still struggle with informal flows; Australia’s key gap is coverage and consistency rather than the performance of the regulated schemes themselves.

Bottom line:
Australia is respectable but incomplete – a reasonably modern stewardship framework, but not yet scaled to the full e-waste problem.

Jurisdiction	Policy Model	Key Features	Strengths	Weaknesses / Gaps
European Union (EU)	Comprehensive EPR + Circular Economy	WEEE Directive mandates producer responsibility; high collection & recycling targets; RoHS hazardous substance restrictions; eco-design rules; strong enforcement.	Global benchmark; broad product coverage; strong alignment of design and recycling; high recycling targets.	Persistent informal flows; uneven performance between member states; complexity for producers.
Japan	Consumer Fee + Producer Obligation	Home Appliance Recycling Law; consumer recycling fees; mandatory take-back via retailers; high mandated recycling rates; small EEE program for municipalities.	High-quality recycling; clear allocation of responsibility; strong roles for retailers and certified recyclers.	Consumer fees may discourage proper disposal; limited coverage beyond targeted categories.
South Korea	Resource Circulation + EPR + Eco-design	Recycling obligations for producers; hazardous substance limits; eco-design requirements; strong focus on precious metals recovery.	Integrates recycling with resource security; robust producer obligations; good performance for high-value devices.	Enforcement challenges for small producers; rapid product turnover strains system.
China	Centralised Fund Model + Regulated Recyclers	National WEEE Fund financed by producer/importer fees; subsidies paid to licensed recyclers per unit; defined product catalogue; strict licensing.	Large-scale system; strong central financing; growing formal recycling sector.	Significant informal recycling persists; regional enforcement uneven; system under financial pressure.
Canada	Provincial EPR Schemes	Provinces run EPR programs for electronics; producers fund collection & recycling; growing harmonisation across provinces.	Mature EPR structure; broad coverage in many provinces; industry-funded.	Fragmented regulatory landscape; variable targets and enforcement.
United States	State-Level Patchwork + Voluntary Certification	Some states have electronics EPR laws; EPA guidance; voluntary recycler standards (R2, e-Stewards). No federal e-waste law.	Innovation in private certification; strong private sector recycling in some states.	No national framework; inconsistent rules; high levels of e-waste export.
Australia	Targeted National EPR + State Landfill Bans	National Television & Computer Recycling Scheme (NTCRS); B-cycle for batteries; Product Stewardship Act; VIC & WA landfill bans; planned expansion to small electronics & solar PV.	Modern stewardship architecture; strong performance in regulated categories; expanding circular economy agenda.	Narrow coverage; no national landfill ban; limited repair/reuse integration; limited focus on PV & EV batteries (but changing).

5. Expected future direction for Australia

Based on current policy signals, inquiries and consultations, you can reasonably expect:

Mandatory national stewardship for small electronics and solar PV
- The Wired for Change process and ministerial priority lists strongly suggest a move to mandatory producer responsibility for small electricals and PV, likely building on NTCRS architecture (co-regulatory arrangements, producer funding). (Google Cloud Storage)
Progressive expansion of landfill bans
- With Victoria (2019) and WA (2024) already in, other states may move in that direction, particularly if Commonwealth stewardship schemes underwrite collection and processing capacity. (Essential Services Commission)
Tighter integration with circular economy and critical minerals policy
- The 2024 National Waste Policy Action Plan and Productivity Commission work on the circular economy both frame e-waste as a materials and value-recovery issue, not just pollution control, which points towards more emphasis on high-value metals recovery and domestic reprocessing. (DCCEEW)
Stronger regulation of batteries and embedded electronics
- Recent ACCC and B-cycle decisions, plus fire and safety concerns, are already pushing towards compulsory stewardship and better design for batteries, including embedded batteries in devices. (B-cycle)
More focus on data security, social outcomes and reuse
- Public commentary highlights privacy and data-breach risks in discarded devices, and the growing role of social enterprises refurbishing phones and laptops for disadvantaged groups. (The Guardian)

6. Guidance – how should Australia proceed?

If you were sketching a direction-setting brief for government, the big moves would look something like this:

1. Move to comprehensive EPR across all e-products

Extend mandatory stewardship to all major e-product categories (small appliances, large whitegoods, PV, EV and stationary batteries, IoT devices).
Make producer fees eco-modulated – cheaper for durable, repairable, non-toxic, high-recycled-content products; more expensive for short-lived or hard-to-recycle designs. This pushes the design problem back up the chain, in line with EU practice. (Environment)

2. Implement a national e-waste-to-landfill phase-out

Use the Victorian and WA models to design a staged national ban, starting with high-toxicity, high-value streams (TVs/PCs, small electronics, batteries, PV) and moving outward. (Essential Services Commission)
Pair this with guaranteed access: minimum collection infrastructure standards (e.g. within X km for regional communities), supported by Commonwealth–state funding deals.

3. Tighten targets, transparency and enforcement

Set clear national collection and recycling targets for each category, aligned with or moving towards EU-style levels, and require annual public reporting. (Environment)
Strengthen compliance powers for the regulator under the Recycling and Waste Reduction Act, including sanctions for free-riding producers and under-performing schemes.

4. Hard-wire repair, reuse and right-to-repair into policy

Introduce right-to-repair measures: access to spare parts, repair information, and standardised connectors/parts where feasible.
Integrate reuse and refurbishment targets into stewardship schemes (e.g. minimum proportion of collected devices prioritised for reuse before recycling).
Fund/partner with social enterprises that refurbish devices for low-income households, schools and community groups, with strict data-destruction standards. (The Guardian)

5. Strengthen export controls and traceability

Tighten Basel Convention implementation and reporting for e-waste, learning from recent exposés of US exports to Asia. (AP News)
Require stewardship schemes to maintain chain-of-custody data, including where material is processed and what standards apply.
Encourage uptake of international best-practice recycler certifications but back them with audit and enforcement rather than relying purely on voluntary schemes.

6. Plan explicitly for the solar PV and large-battery wave

Finalise the solar PV and small electricals scheme with robust producer obligations and clear end-of-life responsibilities for panels and inverters. (Google Cloud Storage)
Develop separate or linked arrangements for EV and stationary batteries, focusing on safe collection, transport, dismantling and high-value materials recovery (lithium, cobalt, nickel, etc.).

7. Integrate e-waste with critical minerals and regional development

Treat e-waste as a secondary mining sector: GEM 2024 estimates billions of dollars in recoverable resources globally; e-waste recycling can complement Australia’s primary mining of critical minerals. (UNITAR)
Target some reprocessing and remanufacturing capacity to regional centres, pairing jobs and skills policies with stewardship-funded infrastructure.

7. Where this leaves Australia

In short:

Problem: very high per-capita e-waste, modest formal recycling, and a looming wave of PV and battery waste. (The Guardian)
Strengths: modern product stewardship framework, successful flagship schemes (NTCRS, B-cycle), and an emerging circular-economy policy spine. (DCCEEW)
Gaps: incomplete product coverage, uneven landfill controls, limited repair/reuse integration, and patchy data/export oversight.

If Australia leans into comprehensive EPR, national landfill bans, right-to-repair and stronger export controls, it can move from being a solid mid-tier performer to a front-runner, while also strengthening critical-minerals security and regional jobs.

Shifting sands: has the energy transition shifted economic and geopolitical power towards China?

The energy transition has shifted a chunk of geopolitical leverage from traditional hydrocarbon exporters toward countries that dominate clean-tech manufacturing and mineral refining, above all China. But the shift is uneven: several upstream miners (Australia, Indonesia, Chile, DRC) also gained bargaining power, while the U.S./EU/Japan are racing to “de-risk” by onshoring and diversifying.

Here are some data points.

Solar supply chain: China’s share of every major PV manufacturing stage (polysilicon, ingots/wafers, cells, modules) now exceeds 80%, after >US$50B of investment since 2011—giving Beijing price-setting and export leverage across a keystone technology of the transition. IEA
Wind turbines: Chinese OEMs (Goldwind, Envision, MingYang, Windey) topped global turbine rankings in 2024, and China accounted for ~60% of global turbine production capacity; Europe and the U.S. trailed at ~19% and ~9% respectively. This consolidation has already triggered EU subsidy probes—an indicator of strategic dependence concerns. Wood Mackenzie+1
Batteries & components: China regained #1 in BloombergNEF’s 2024 lithium-ion supply-chain ranking and controls a dominant share of cell manufacturing and key components (cathodes/anodes), reflecting deep midstream strength. The U.S. EIA estimates China made ~85% of battery cells by value and 74% of battery packs/components exports in 2023. BloombergNEF+1
Critical-minerals refining choke points: IEA’s 2025 outlook finds refining is more concentrated than mining; for most transition minerals, China’s share rose to ~86% in 2024, with China the leading refiner for 19 of 20 minerals (avg. ~70% share). That midstream dominance is where geopolitical leverage bites. IEA+1
Rare earths & magnets: China provides ~70% of rare-earth mine output and ~85–90% of processing. It has tightened regulatory control over the sector and previously restricted magnet-making know-how—leveraging a classic choke point (NdFeB magnets are used in wind turbines/EVs). In 2024 the U.S. still sourced ~70% of rare-earth compounds/metals from China. U.S. Geological Survey+1
Graphite (EV anodes): China refines >90% of battery-grade graphite and in 2023 imposed export licensing on certain graphite products—an explicit use of supply-chain leverage. IEA highlights persistent concentration risks here. fticonsulting.com+1
Gallium/germanium controls: Beijing’s 2023–24 export restrictions on gallium and germanium—metals crucial for chips, sensors and some clean-tech electronics—demonstrated coercive capacity rooted in ~98% and ~68% shares of global output respectively. CSIS+1
According to a study by the United States Studies Centre at the University of Sydney, Australia imports about 96% of its solar modules from China. ussc.
Counter-balancing shifts upstream: Resource holders have not been sidelined—some gained power by forcing domestic value-add. Indonesia’s nickel ore export ban (from 2020) pulled in large Chinese investment and made Indonesia the center of new HPAL/refining capacity, reshaping EV supply chains. Australia remained the largest lithium miner (2024), though much is refined in China—illustrating miners’ leverage tempered by midstream dependence. Investing News Network (INN)+3IEA+3IEA+3

Summary: Traditional petrostates still matter for oil & gas during the transition, but strategic leverage is clearly migrating to midstream refining and manufacturing nodes—and today those nodes are overwhelmingly in China. That’s why the U.S., EU, Japan and Australia are pouring money into non-Chinese refining (e.g., rare-earths via Lynas in Malaysia) and local clean-tech factories, and why Beijing’s targeted export controls immediately move markets. Reuters+2wsj.com+2

Not divided not conquered: Samuels Review finally hits home

Last 7 days

Bill introduced & sales pitch: The government tabled its Environment Protection Reform Bill 2025, pitching it as a fix for slow approvals and stronger protections, with a push to pass it by year-end. Reuters+2Minister for the Environment and Water+2
No split: The Coalition asked to split streamlining from tougher protections; Labor and key business voices rejected that, saying a split kills certainty. ABC+2ABC+2
Ministerial “override” flashpoint: Drafts indicate a national-interest override letting the minister approve projects inconsistent with new standards—Watt says it won’t be used for coal/gas; critics call it a carve-out. The Guardian+1
Climate “trigger” ruled out: The bill won’t include a climate trigger to block high-emitting projects; instead, emissions disclosure/mitigation plans are flagged. Greens say that’s not enough. ABC
Stakeholders diverge: Business wants clarity and speed; environment groups warn about discretion, offsets, and enforcement teeth; Greens want a climate test. Reuters+2ACF+2

What’s in the bill (headlines)

National Environment Standards with an “unacceptable-impact” test to knock out projects with irreversible harm up-front. Reuters+1
Independent EPA-style regulator for compliance/enforcement, while final approvals stay with the minister (subject to published reasons). The Canberra Times+1
Streamlined approvals via clearer rules and fewer Commonwealth/State duplications. Reuters
Offsets/restoration pushed toward “net-positive”/“nature-positive” outcomes (details still contentious). Allens
Harsher penalties & stop-work powers to lift compliance. Reuters

Where the fights are

Override power: Environmental groups fear the national-interest override blunts the standards; government says it’s narrow and accountable. The Guardian+1
Climate test: No climate trigger is a hard red line for the Greens; Labor argues Samuel didn’t recommend one and prefers other climate tools plus disclosure. ABC
Offsets & “net-positive”: Concerns over like-for-like, permanence, and leakage. ACF
Split vs package: Business and Labor want a single package; Coalition still pressing for a split to fast-track approvals. ABC+1
Litigation risk: Lawyers flag early court tests around definitions (eg, unacceptable impact, override scope). Capital Brief

How it lines up with the 2020 Samuel Review

Samuel Review (2020)	Bill direction this week
Legally enforceable National Environment Standards; decisions (including accredited state processes) must be consistent with them. Rare, reasoned public-interest override permitted. DCCEEW	Standards form the core; unacceptable-impact gate built in. A national-interest override is included with reasons—exact guardrails are politically hot. Reuters+1
Independent compliance & enforcement separated from politics (EPA-like office). DCCEEW	EPA-style regulator created for monitoring/enforcement; minister retains approvals. Debate is over independence/teeth. The Canberra Times
Streamline & accredit states against Standards to cut duplication. DCCEEW	Streamlining is central—explicit aim to reduce duplication/timeframes. Reuters
Better data & measurable standards; move toward granular, quantitative tests. DCCEEW	Directionally aligned; details on datasets/thresholds still to surface publicly. Reuters
Climate: consider climate scenarios in impact/avoid-mitigate hierarchy, but no separate “climate trigger” in EPBC. DCCEEW	No climate trigger (consistent with Samuel’s framing), with emissions disclosure/mitigation planning instead. ABC

Kamchatka shaky: 8.8 one of the largest in history – highlights Fukushima learnings and instant Pacific tsunami warning effect

1. Event Overview

On July 30, 2025, at around 07:01 UTC, a powerful earthquake with a moment magnitude of 8.8 struck approximately 119 km east‑southeast of Petropavlovsk‑Kamchatskiy, Kamchatka Peninsula, Russia. It’s the strongest earthquake in the region since 1952 (Reuters) and one of the largest ever recorded. Lucky it didn’t hit in a vulnerable heavily-populated area! Longe-range tsunami warnings across the Asia-Pacific did their job and were triggered immediately, with emergency warnings issued in Russia itself, and Japan and Hawaii.

2. Geological Details

• Depth & Epicenter

The quake occurred at a shallow depth of ~19 km (12 miles) beneath the seafloor (Reuters).

• Tectonic Context & Cause

This rupture occurred along the Kuril‑Kamchatka subduction zone, where the dense Pacific Plate subducts beneath the Okhotsk Plate at convergence rates of ~86 mm/yr. These megathrust-type earthquakes generate the largest events in this region (Wikipedia).

• Aftershocks

Several strong aftershocks followed, with magnitudes up to ~6.9, as noted by the USGS and local monitoring authorities. Although aftershock activity is ongoing, no significantly larger main shocks are expected in the near term (Reuters).

3. Damage & Regional Impact

• Russia’s Far East

Severo‑Kurilsk and surrounding coastal settlements experienced partial flooding from tsunami waves up to ~4 m high.
A kindergarten was damaged, and there were reports of power outages in Sakhalin region.
Several injuries, including people hurt during evacuation or jumping from windows, but no confirmed fatalities (Reuters, Sky News).

• Japan

Extensive evacuations, especially in Hokkaido and northeastern coastal regions, with over 900,000 people advised to move.
Tsunami waves of up to ~60 cm (~2 ft) were recorded; no damage or casualties reported.
Fukushima nuclear plant workers were evacuated as a precaution; no abnormalities observed (The Guardian).

• Pacific Basin (Hawaii, U.S. West Coast, Canada, etc.)

In Hawaii, tsunami waves of approximately 1–1.2 m (3–4 ft) struck—robust evacuation alerts were issued, though no major damage reported so far. Some small flooding occurred in shoreline zones.
Tsunami watches extended along the West Coast of the U.S., British Columbia, Alaska, Guam, Ecuador, New Zealand, and other Pacific coastal areas; wave heights up to 1–3 m were forecast in many locales (CBS News, Reuters, News.com.au, The Guardian, The Washington Post).

4. Tsunami Risk & Response

Immediate tsunami warnings issued across the Pacific (see network map below): including Hawaii (see Hawaii box below), Japan, the U.S. West Coast, Canada, New Zealand, Ecuador, Guam, among others (People.com, The Guardian, News.com.au).
Recorded wave heights:
- Kamchatka/Severo‑Kurilsk: up to ~4 m
- Hawaii: ~1–1.2 m recorded
- Japan: up to ~0.6 m
Evacuation orders, port closures, and emergency shelters activated widely. NWS and local authorities stressed prolonged risk as multiple waves and strong currents continued (Reuters, The Wall Street Journal, News.com.au).

5. Implications & Broader Significance

This quake is among the six strongest recorded globally, and the largest in Kamchatka since the 1952 Mw 9.0 Severo‑Kurilsk earthquake, which generated ~18 m tsunamis and caused widespread devastation in the Kuril Islands (Wikipedia).
Highlights ongoing seismic and tsunami risk in subduction zones along the Pacific “Ring of Fire.”
Underlines the critical importance of early warning systems, evacuation plans, and preparedness—especially given lessons from past events (e.g., 2011 Tōhoku, 1952 Kuril) (forms2.rms.com).
In Japan, the event prompted reflection on resilience of nuclear infrastructure and continued community readiness.

6. Summary Table

Aspect	Details
Date & Time	July 30, 2025; ~07:01 UTC
Magnitude	8.8
Depth	~19 km (12 miles)
Epicenter	119 km ESE of Petropavlovsk-Kamchatsky, Kamchatka
Tectonic Setting	Megathrust along Kuril‑Kamchatka Trench
Aftershocks	Series up to ~6.9; ongoing, no stronger quake expected
Damage	Flooding, damage to infrastructure, injuries in Kamchatka
Tsunami Impact	4 m at origin, smaller waves further afield
Evacuations Issued	Russia, Japan (900,000 people), Hawaii, Pacific coasts
Fatalities	None confirmed
Significance	Largest since 1952; underscores subduction-zone hazard

NEM mid-July update

Here’s a high-level snapshot of the National Electricity Market for July 1–17, 2025:

Spot Prices
Wholesale spot prices have remained elevated into mid-winter. June 2025 saw an average NEM spot price of $232/MWh (up 139% on May’s $96/MWh) (Leading Edge Energy). By July 11, instantaneous trading prices in the 08:30–09:00 interval were around $183.11/MWh (nems.emcsg.com).
Major Generation Outages
Planned and unplanned outages have tightened supply: Yallourn Unit 3 was offline Jul 5–12 for a scheduled overhaul (560 MW), and Eraring Unit 5 tripped unexpectedly Jul 10–14 (~720 MW) (nemoutages.azurewebsites.net, aemo.com.au).
Wind & Solar Output
Solar and wind continue to contribute strongly. AEMO forecasts overall solar curtailment under 1% but notes some large plants face >25% cuts due to network constraints (PV Magazine Australia); real-time data show combined wind+solar often exceeding 3.5 GW during daylight peaks (aemo.com.au).
Renewables Share
In Q1 2025, renewables supplied a record 43% of NEM energy (ecogeneration.com.au); mid-July month-to-date renewable penetration remains above 40%, driven by wind, solar and hydro (aemo.com.au).
Hydro News
Snowy Hydro’s Snowy 2.0 pumped-storage project has completed key factory acceptance testing, keeping its 2.2 GW/350 GWh in-system by 2028 on track (Snowy Hydro, Snowy Hydro).
Battery News
Fluence was selected for the 300 MW/600 MWh Wellington BESS, due to start construction Q4 2025 (Yahoo Finance). Envision Energy and FERA Australia also inked a deal to build up to 1.5 GWh of storage alongside 1 GW of wind generation (Taiwan News).
Major Price Spikes & Negative Events
A cold snap on June 11 drove spot prices above $7,000/MWh in all five regions during evening peaks (WattClarity). Conversely, high solar export/low overnight demand has triggered multiple negative-price dispatch intervals, with the market floor at -$1,000/MWh observed in early July (utilizer.com.au, aer.gov.au).

VNI West and the Challenges of Transitioning Australia’s Grid

AKA another budget and timeline blowout…….

The Victoria to New South Wales Interconnector West (VNI West) is one of Australia’s most significant energy infrastructure projects. Designed to connect renewable energy zones across Victoria and southern NSW, the project is a critical component of the Australian Energy Market Operator’s (AEMO) Integrated System Plan (ISP). It aimed to support the decarbonisation of the National Electricity Market (NEM) and provide reliable, low-emissions energy to homes and businesses.

Project Scope and Origins

The project:

VNI West is a proposed 500 kV double-circuit transmission line, approximately 240 km long.
It will connect the Western Renewables Link in Victoria to Transgrid’s Dinawan substation in southern NSW.
The initial proposal appeared in AEMO’s ISP in 2018, with formal cost-benefit analysis undertaken via the Regulatory Investment Test for Transmission (RIT-T) process.
AEMO and Transgrid completed the Project Assessment Conclusions Report (PACR) in May 2023.
Transmission Company Victoria (TCV), established by AEMO, is the project proponent in Victoria.

Governance, Financing, and Ownership

To understand how VNI West is progressing, it is important to examine how the project is being managed and financed.

The project is overseen by AEMO and the Australian Energy Regulator (AER).
Transgrid leads the NSW portion; TCV leads the Victorian portion.
The project will ultimately be owned by the successful bidder for TCV, likely to be one of the consortia shortlisted by AEMO.
Financing includes:
- Estimated project cost: AUD $3.96 billion (2022–23 dollars).
- Federal government concessional finance via Rewiring the Nation: AUD $750 million.
- CEFC concessional loan: AUD $140 million.
- Private equity: nearly AUD $700 million committed by Transgrid security holders.

Budget Overruns and Delays

Despite its promise, VNI West has encountered several challenges, particularly around cost and timing.

VNI West was initially planned to be operational by 2028.
Delays have pushed the delivery timeline to late 2030.
Cost inflation across transmission components (lines, substations, materials) has increased the project’s cost base by up to 55%.
Regulatory and landholder engagement processes have further delayed the project.

Broader Cost Blowouts

VNI West is not alone in facing overruns. A comparison with other major infrastructure projects reveals a common trend.

Project	Owner/Developer	Original Budget & Timeline	Revised Budget & Timeline
VNI West	TCV / Transgrid	$3.96 bn, due 2028	+55% cost, delivery now 2030
Snowy 2.0	Snowy Hydro	$2 bn (2017), due 2021	$12 bn; full delivery by 2028
HumeLink	Transgrid	$1.35 bn, due ~2028	~$5 bn, timeline under review
EnergyConnect (NSW-SA)	Transgrid / ElectraNet	~$2.3 bn, due 2024-25	Delays ongoing, cost increases noted

Reasons for Overruns

These cost and timeline blowouts are driven by a complex interplay of factors.

Cost escalation in raw materials, skilled labour shortages.
Complex geotechnical conditions (e.g., Snowy 2.0 tunnel delays).
Environmental and cultural heritage assessments extending planning timelines.
Strong community resistance to transmission lines and land access issues.

Coal Generator Closure Schedule

The timing of new infrastructure like VNI West was meant to be closely tied to the scheduled closure of existing coal-fired generators. These closure dates are approaching, and not surprisingly, governments are looking to do deals to keep them open a bit longer.

Station	State	Capacity (MW)	Owner	Commissioned	Planned Closure
Yallourn	VIC	1,480	EnergyAustralia	1973	2028
Loy Yang A	VIC	2,210	AGL	1985-1994	Mid-2030s
Eraring	NSW	2,640	Origin Energy	1982-1984	2027*
Liddell	NSW	2,000	AGL	1971	2023 (closed)
Hazelwood	VIC	1,600	Engie (formerly)	1971	2017 (closed)

*Note: The NSW government is exploring an extension of Eraring’s operation beyond 2027 due to market supply concerns.

Debate For and Against VNI West

The VNI West project has sparked a significant public and policy debate. Supporters argue the project is essential for integrating renewables and replacing coal. Critics point to high costs, environmental concerns, and community opposition.

In Support:

Unlocks over 3 GW of renewable generation capacity.
Reduces electricity prices by lowering congestion and allowing excess renewables to be exported.
Supports system reliability and coal retirements.

Against:

High cost and long delivery timeline may not match urgent coal closure dates.
Strong community opposition from landholders and regional communities.
Environmental impact and landscape fragmentation.
Suggestions for alternative routes or underground cabling not adopted.

Conclusion

The VNI West project exemplifies the multifaceted challenges of Australia’s energy transition. While the need for expanded transmission is undeniable in the face of imminent coal closures, the social, engineering, geotechnical, and financial barriers are substantial.

A key issue highlighted by VNI West and other large energy infrastructure projects, is the inadequacy of initial costing and scheduling processes. Project proponents often release cost estimates early in the planning phase. These early-stage costings are showing to be optimistic and do not account for the long lead times and inevitable delays caused by regulatory approvals, stakeholder negotiations, and construction challenges.

By the time projects reach the construction phase—sometimes several years after initial estimates—the cost environment has changed substantially. Materials, labour, land access, and financing costs can escalate well beyond original assumptions, rendering initial budgets obsolete. There is now ample evidence, particularly from projects like Snowy 2.0, HumeLink, and VNI West, that initial estimates are regularly exceeded by billions of dollars.

Planners and regulators need to build greater contingency—or “fat”—into early cost projections. Future-proofing cost estimates with higher allowances for inflation, uncertainty, and delay risk would provide a more honest representation of total project cost. This approach would not only enhance financial transparency but also improve public confidence in the delivery of critical infrastructure.